1. Field of the Invention
The present invention relates to predicting and modeling changes in capillary pressure and relative permeabilities in a porous medium due to mineral precipitation and dissolution for reservoir simulators or reactive transport codes.
2. Description of the Related Art
In the oil and gas industries, massive amounts of data are required to be processed for computerized simulation, modeling and analysis for exploration and production purposes. For example, the development of underground hydrocarbon reservoirs typically includes development and analysis of computer simulation models of the reservoir, as well as reactive transport models of the reservoir. These underground hydrocarbon reservoirs are typically complex rock formations which contain both a petroleum fluid mixture and water. The reservoir fluid content usually exists in two or more fluid phases. The petroleum phase in reservoir fluids is produced by wells drilled into and completed in these rock formations. The water phase of the reservoir fluid over time changes both the capillary pressure and relative permeabilities of the formation rock.
A geologically realistic model of the reservoir, and the presence of its fluids, also helps in forecasting the optimal future oil and gas recovery from hydrocarbon reservoirs. Oil and gas companies have come to depend on geological models as an important tool to enhance the ability to exploit a petroleum reserve. Thus, it is important that the models formed in reservoir simulation and reactive transport models accurately represent petrophysical parameters of the reservoir over times of interest.
Mineral dissolution and precipitation reactions in subsurface porous media can alter the structure of the pore network and thus significantly impact porosity, permeability, capillary pressure, and relative permeabilities. These effects should be accurately captured in modeling reactive transport (coupled fluid flow and chemical reaction) in reservoirs so that the modeling is more indicative of the fluid content of the reservoir and its movement over times of interest.
Traditionally, reaction-induced changes in permeability have been estimated using empirical relationships, such as the Kozeny-Carmen equation. Relative permeabilities are assumed to be unchanged after mineral precipitation or dissolution, while changes in capillary pressure is approximated by using a Leverett scaling relation. This treatment, however, assumed that mineral dissolution and precipitation reactions occurred in all the pores. So far as is known, the prior art ignored the important fact that for multiphase flow, these reactions actually occur in pores occupied by the water phase of the multiphase flow. As a result, these traditional approaches are applicable to single-phase flow condition only, while multiphase flow occurs very often in oil and gas reservoirs.
Although some have taken into consideration that chemical reactions happen in the aqueous phase when dealing with a permeability change, practical approaches to accurately estimate effects of mineral dissolution and precipitation reactions on multiphase flow properties are not yet, so far as is known, available.
In Mezghani, (U.S. Published Application No. 2014/0350860) determining capillary pressure in a basin/reservoir is disclosed. Well log data is obtained that includes permeability log data, porosity log data, water saturation log data, and oil saturation log data. A processing methodology is described to obtain the capillary pressure of the reservoir or basin. Measures known as Thomeer parameters for a multi-pore system of a Thomeer model are determined by evaluating an objective function that measures the mismatch between the well log data and modeled data having the Thomeer parameters as input. The objective function is iteratively evaluated using linear equality constraints, linear inequality constraints, and nonlinear equality constraints until convergence criteria are met. The effects of mineral dissolution and precipitation reactions on multiphase flow properties are not taken into account.
Chen (U.S. Pat. No. 7,567,079) relates to determining capillary pressure and relative permeability. However, the determination is in connection with core plugs taken from formations, rather than in connection with reservoir simulation or reactive transport codes. Montaron (U.S. Pat. No. 7,716,028) discloses a system which uses a wettability logging tool to obtain data for generation of a three dimensional wettability map in connection with modeling a reservoir. O'Meara (U.S. Pat. No. 7,054,749) deals with determining reservoir parameters such as fluid volumes, fluid contacts and permeability in geological subsurface models. Georgi (U.S. Pat. No. 7,825,659) shows techniques for adjusting grain size of pore-scale geometric models of an earth formation by matching nuclear magnetic resonance (NMR) distribution from the model to measured NMR distribution data obtained from NMR well logs such as shown in FIGS. 1 and 2 of the drawings. Hustad (U.S. Published Application 2010/0114506) involves determining capillary pressures in a multi-phase fluid reservoir. However, in each of the foregoing references as in the Mezghani reference, the effects of mineral dissolution and precipitation reactions on multiphase flow properties are not taken into account.